In the oil and gas industries, coiled tubing refers to a very long metal pipe supplied spooled on a large reel. It is used for interventions in oil and gas wells and sometimes as production tubing in depleted gas wells. A relatively modern drilling technique involves using coiled tubing instead of conventional drill pipe.
FIG. 1 illustrates generally a coiled tubing setup. The coiled tubing is fed from a reel into the injector which effectively powers the tubing into the wellhead. The end of the coiled tubing string can be outfitted with numerous downhole tools including drill bits and other related drilling equipment. The “gooseneck” or tubing guide is the angled piece on the injector which guides the tubing and allows a bending of the coil string to allow it to go through the injector. It is what guides the tubing from the reel and directs the tubing from an upwards angle and turns it into a vertical down position into the injector and through a blow-out preventer (BOP) stack into the wellhead. The injector and tubing guide are connected together and are suspended by a crane or similar lifting methods for operations.
The main engine of a coiled tubing unit is the injector head, which contains the mechanism to push and pull the coiled tubing in and out of the hole. The injector head includes motors powered by hydraulic fluid. The hydraulic motor then turns a shaft positioned horizontally through the top portion of the injector into a gearbox. The gearbox is configured to reduce the output of the motor to provide functional response to a shaft which powers large cog type gears, e.g., sprockets, or any drive style component, which in-turn moves drive chains to be moved along with gripper blocks that move the tubing along its path in or out the well.
Injector breakdowns during operation can have disastrous results, for personnel, equipment, safety, and cost effectivity. The injector is typically suspended high above the well being serviced. Any failure of an injector head motor or gearbox during operation would pose a situation in which the tubing inside the injector would become stuck, and have to be severed to move the injector off of the wellhead to perform service. Prior to cutting the string of tubing, all pumping operations must also cease. The tubing must be severed at a precise angle, the tubing guide removed, and carefully positioned as to not pose danger the crew or equipment. The injector can be forcefully removed by crane, and then it has to set on either the trailer or ground for gearbox replacement. The injector is then repositioned over the string and the tubing guide is re-installed and the tubing is then clamped together above the gripper blocks as to not place a strain on the clamp, and the remaining pipe down in the well is removed. During the breakdown, if it is possible, well circulation needs to continue to allow the tubing to be removed, if the circulation is not maintained, it may result in well bore damage. This entire process, if no issues arise, may typically last 18-30 hours, or more, depending on the skillset and tools available for the crew. This is highly dependent on having a spare gearbox on hand, which is a very expensive and heavy item and is not typically stocked by a crew as a spare part. Gearboxes can weight anywhere from 300 lbs to 1,000 lbs or more depending on the size of the injector, challenging work crews with logistical issues even with the most simple repair.
On prior injector heads the gearbox is mounted on one side of the injector head and connects to a driveline or shaft running horizontally from the hydraulic motor through the chassis connecting to the gearbox. The gearbox, motor, and transfer shaft running between the gearbox and motor are the sole support structure for the chains, gripper blocks and the entire coil tubing string from the reel to the well. Removing the gearbox while the injector is in the normal operating position is not an option because the motor and sprocket shaft are unable to support the mass of the entire unit. Accordingly, prior injector heads cannot be serviced under load, or not under load for this reason. All prior injector head gearboxes have to be removed with the unit disabled from the well and a disassembly of the chain and drive components in order to remove the gearbox. This method is extremely time consuming and poses a risk for equipment and personnel lifting and moving an injector off the well. Another method of teardown is to lay the injector on the side for gearbox removal.
FIG. 1 illustrates a prior coiled tubing injector 200. The prior coiled tubing injector 200 configuration includes a motor 201 and a gearbox 205, and a transfer shaft 202 connecting the gearbox 205 to the motor 201. The gearbox 205 input is connected to the transfer shaft 202 by mating splines. The gearbox 205 output is connected to the sprocket drive shaft 204 by mating splines. The shaft 204 is not mounted to the chassis of the injector 200, and is instead mounted by the splines, within the inner structure of the gearbox 205. If the gearbox is removed while the injector is vertical, the support structure is unable to support the weight of the chain sprockets 203, and the chain 206 will be unable to support the weight of the tubing and fail structurally.
There have been no approaches or solutions to designing or implementing a structure that would allow a gearbox, motor, shaft or any other upper driveline component to be changed out while the injector is in operation, or not operation or any other configuration while the injector is vertical. What is needed then is an improved coiled tubing injector head driveline.